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VAALCO Energy, Inc., a Delaware corporation incorporated in 1985, is a Houston-based independent energy company principally engaged in the acquisition, exploration, development and production of crude oil and natural gas. VAALCO owns producing properties and conducts exploration activities as an operator in Gabon, West Africa, conducts exploration activities as an operator in Angola, West Africa, conducts exploration activities as a non-operator in Equatorial Guinea, West Africa, and has conducted exploration activities as a non-operator in the British North Sea. VAALCO is the operator of unconventional and conventional resource properties in the United States located in Montana, South Dakota, and North Texas. The Company also owns minor interests in conventional production activities as a non-operator in the United States. As used in this report, the terms â€śCompanyâ€ť, â€śweâ€ť, â€śusâ€ť, â€śourâ€ť, and â€śVAALCOâ€ť mean VAALCO Energy, Inc. and its subsidiaries, unless the context otherwise requires. The Companyâ€™s corporate headquarters are located at 4600 Post Oak Place, Suite 300, Houston, Texas 77027 where the telephone number is (713) 623-0801.

The Companyâ€™s international strategy is to pursue selective opportunities with a focus on West Africa that are characterized by reasonable entry costs, favorable economic terms, high reserve potential relative to capital expenditures and the availability of existing technical data that may be further developed. The Company believes that it has strong management and technical expertise with proven abilities in identifying international opportunities and establishing favorable operating relationships with host governments and local partners familiar with the local practices and infrastructure. The Company owns producing properties and conducts exploration activities as operator of two exploration licenses in Gabon, one exploration license in Angola, and as non-operator of one exploration license in Equatorial Guinea.

In addition, the Companyâ€™s production strategy is to maximize the value of the reserves discovered in Gabon through exploitation of the offshore Etame Marin block (comprised of the Etame, Avouma, South Tchibala, and Ebouri producing fields, the Southeast Etame and North Tchibala fields currently being developed), and the onshore Mutamba Iroru block (Nâ€™Gongui field currently being developed).

Domestic

The Companyâ€™s domestic strategy is to selectively acquire resource based properties, including liquids-rich shale properties. In 2010 and 2011, the Company acquired a total of two small leases in the Granite Wash formation in Texas, followed by two larger properties acquired in 2011 located in the Middle Bakken formation in Montana, and one property acquired in 2012 located in the Red River formation in South Dakota. With the limited drilling success experienced in 2012 on the recently acquired properties, the Company expects to be very selective on future domestic property acquisitions.

RECENT DEVELOPMENTS

Offshore Gabon

The Companyâ€™s primary source of revenue is from the Etame Production Sharing Contract related to the Etame Marin block located offshore the Republic of Gabon. VAALCO operates the Etame Marin block on behalf of a consortium of companies. At December 31, 2012, VAALCO owned a 30.35% interest in the exploration acreage within the Etame Marin block. The Company owns a 28.1% interest in the development areas in and surrounding the Etame, Avouma, South Tchibala, and Ebouri fields, each of which is located on the Etame Marin block. The development areas were subject to a 7.5% back-in by the Government of Gabon, which occurred for these fields after their successful development. The Southeast Etame and North Tchibala fields, each of which is also located on the Etame Marine block are in the process of being developed and will also be subject to a 7.5% back-in by the Government of Gabon.

The Company produces from the Etame, Avouma, South Tchibala and Ebouri fields on the block. During 2012, these fields produced approximately 7.0 million Bbls (2.0 million Bbls net to the Company). The Companyâ€™s share of barrels sold reflects an allocation of cost oil and profit oil, and a reduction for royalty (13%).

In July 2012, the Company discovered the presence of hydrogen sulfide (H2S) from two of the three producing wells in the Ebouri field. The wells were shut-in for safety reasons resulting in a decrease of approximately 2,000 BOPD or approximately 10% of the gross daily production from the Etame Marin block. Analysis and options for re-establishing production from the impacted area was undertaken in the second half of 2012. The expected outcome is that additional capital investment will be required, which is likely to include a new platform-type structure with H2S processing capability, and new wells to re-establish production from the impacted area. The design, cost projections and final investment decisions by the Company and its partners are expected to be made in 2013. Re-establishing production from the area impacted by H2S is expected in the first half of 2016.

During 2011 and 2012, the Company invested in platform modifications to both the Ebouri and Avouma offshore platforms to accommodate the drilling of additional wells in addition to upgrading the electrical and power generation systems on both platforms. A new personnel accommodation module was installed during 2012 at the Avouma platform. In 2012, the Company also finished the construction and installation of water knock-out facilities at the Avouma platform. The water knock-out facilities are expected to go on-line in the first half of 2013.

The Company and its partners approved the construction of two additional production platforms in late 2012. One platform will be located in the Etame field and the second platform will be located in-between the Southeast Etame and North Tchibala fields. Multiple wells are expected to be drilled from each of the platforms as part of the future development plans for the Etame Marin block. The Company drilled a successful exploration well in the Southeast Etame area in 2010, which will be developed from the second platform. The expected cost to build and install the platforms during the 2013/2014 timeframe is $275.0 million ($77.0 million net to the Company). The cost of the wells is not included in the platform costs.

A six-well drilling program commenced in December 2012 that includes an exploration well, a development well in the Avouma field, an exploration appraisal well to be drilled in the Ebouri field and three well recompletions to replace electrical submersible pumps.

Onshore Gabon

The Company executed a farm-out agreement in August 2010 with Total Gabon on the Mutamba Iroru block located onshore near the coast in central Gabon. The Mutamba Iroru block contains an exploration area of approximately 270,000 acres. The Company has a 50% working interest on the block. Under the terms of the agreement, the Company and Total Gabon committed to reprocess 400 kilometers of 2-D seismic data and drill one exploration well. The seismic reprocessing work was completed in 2012. The exploration well was drilled in 2012 resulting in a discovery at a cost of $17.1 million ($5.3 million net to the Company). A plan of development is expected to be completed for the Nâ€™Gongui field and submitted to the government of Gabon in 2013.

In 2010, the exploration permit was successfully extended until May 2012 and an application for a further nine-month extension was made in early 2012. In a letter agreement from the government of Gabon, the terms of the extension to March 2013 were agreed upon, yet the extension amendment was not executed by the government of Gabon. The Company and Total are working with the Gabon government in 2013 to finalize the extension and to obtain a further exploration extension. However, the Company can provide no assurances that such a request will be granted. The Company believes the discovery area is not impacted by the uncertainty of the extension agreement as the well was drilled during the contracted period and application of the discovery was timely made to the government of Gabon.

Offshore Angola

In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola. The four year primary term with an optional three year extension awards the Company exploration rights to 1.4 million acres offshore central Angola. The Companyâ€™s working interest is 40%.

By a governmental decree dated December 1, 2010, the government-assigned working interest partner was removed from the production sharing contract for cause, and a one year time extension was granted for drilling the two exploration commitment wells. In early 2012, the Angolan government granted a further one year extension to November 30, 2012 for drilling the two exploration commitment wells in accordance with the production sharing contract. In July 2012, the Angolan government granted an additional two year extension until November 30, 2014 to drill the two exploration commitment wells.

In the second quarter of 2012, the Company identified a potential partner to acquire the available 40% working interest and submitted the name of the interested party to the Angolan government for approval. In November 2012, the government advised the Company that it has entered into negotiations with the potential partner. The Company met with the Angolan government in January 2013 and learned the negotiations are still underway.

Offshore Equatorial Guinea

In July 2012, the Company signed a definitive agreement with PETRONAS CARIGALI OVERSEAS SDN BHD for the purchase of a 31% working interest in Block P, located offshore Equatorial Guinea at a cost of $10.0 million. The acquisition was completed on November 1, 2012. The Company expects two exploration wells will be drilled on this block in 2013 or 2014. GEPetrol, the national oil company of Equatorial Guinea, is the operator of the block.

Onshore Domesticâ€”Texas

The Company acquired a 640 acre lease, the Hefley field, in the Granite Wash formation in North Texas in December 2010 and a 480 acre lease in the same formation in July 2011. Production from a second well in the Hefley field began in April, 2012. During 2012, the two wells produced approximately 10,000 Bbls of oil and 519 million cubic feet of gas net to the Company after deduction of royalty and severance taxes. A financial impairment of $7.6 million was recorded for the Hefley field in the third quarter of 2012 on the basis of production performance, projected hydrocarbon price curves, operating expenses and estimated reserves.

The Hefley field acreage is held by production. The expiration date of the primary term of the second Granite Wash lease is August 2014.

Onshore Domesticâ€”Montana

In May 2011, the Company acquired a 70% working interest in approximately 5,200 acres (3,640 net acres) in Sheridan County, Montana in the Middle Bakken formation. The Company drilled two wells on this acreage in 2012. After completion testing beginning in the fourth quarter of 2012 using electrical submersible pumps (ESPâ€™s), both of the wells drilled have been determined to be unsuccessful as the operating and water disposal costs exceeded the value of the gas and condensate produced from the wells. Dry hole cost and leasehold impairment totaling $14.2 million was recognized in the fourth quarter of 2012 related to these two wells.

In September 2011, the Company acquired a 65% working interest in approximately 22,000 gross acres (14,300 net acres) covering the Middle Bakken and deeper formations in the East Poplar unit and the Northwest Poplar field in Roosevelt County, Montana. Pursuant to the terms of the acquisition, the Company was required to drill three wells at its sole cost, one of which was required to be drilled by June 1, 2012 and the remaining two wells were required to be drilled by the end of 2012. A vertical exploration well, which met the time requirement for drilling the first well, was spudded in December 2011 to evaluate the formations. The second exploration well was drilled and completed in the Bakken/Three Forks formations. Both of these wells were unsuccessful efforts, resulting in dry hole costs and leasehold impairment totaling $18.4 million recorded in the fourth quarter of 2012. The third obligatory well began drilling in December 2012 and is scheduled for completion testing in the Nisku formation in the first half of 2013.

Onshore Domesticâ€”South Dakota

In September 2012, the Company acquired a 100% working interest in approximately 10,000 acres in Harding County, South Dakota, for $1.5 million. The primary objective for this property is the Red River formation. Pursuant to the terms of the acquisition, the Company is obligated to drill and complete a well, or reenter and complete an existing well within twelve months of the acquisition date. Once this obligation is met and within sixteen months of the acquisition date, the Company must elect to proceed or withdraw from the transaction. Should the Company elect to proceed, it must pay an additional amount of approximately $3.6 million and commit to drill and complete an additional well, or reenter and complete another existing well within twelve months of the date the Company elects to proceed with the transaction. The Company drilled the initial well on the property in the first quarter of 2013, an unsuccessful effort at a cost of approximately $2.9 million. The Company will record this amount as dry hole cost in the first quarter of 2013. The Company does not have plans to proceed with additional investments on this property.

AVAILABLE INFORMATION

The Company files annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (â€śSECâ€ť). You may read and copy any document the Company files at the SECâ€™s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the SECâ€™s Public Reference Room. The Companyâ€™s SEC filings are also available to the public at the SECâ€™s website at www.sec.gov .

You may also obtain copies of the Companyâ€™s annual, quarterly and current reports, proxy statements and certain other information filed with the SEC, as well as amendments thereto, free of charge from the Companyâ€™s website at www.vaalco.com . No information from the SECâ€™s or the Companyâ€™s website is incorporated by reference herein. The Company has placed on its website copies of its Audit Committee Charter, Code of Business Conduct and Ethics, and Code of Ethics for the Chief Executive Officer and Chief Financial Officer. Stockholders may request a printed copy of these governance materials by writing to the Corporate Secretary, VAALCO Energy, Inc., 4600 Post Oak Place, Suite 300, Houston, Texas 77027.

CUSTOMERS

Substantially all of the Companyâ€™s oil and gas is sold at posted or indexed prices under short-term contracts, as is customary in the industry. In Gabon, the Company sold oil under contracts with Mercuria Trading NV (â€śMercuriaâ€ť) in 2012 and 2011. In 2010, the Company sold its Gabon oil to Vitol S.A. In both 2012 and 2011, approximately 99% of total sales were made to Mercuria. In 2010, approximately 100% of total sales were made to Vitol S.A. For the 2013 calendar year, the Company will also sell its oil under a contract with Mercuria. While the loss of Mercuria as a buyer might have a material effect on the Company in the short term, management believes that the Company would be able to obtain other customers for its crude oil.

Domestic operated production in Texas is sold via two contracts, one for oil and one for gas and natural gas liquids. The Company has access to several alternative buyers for oil, gas, and natural gas liquids domestically.

EMPLOYEES

As of December 31, 2012, the Company had 103 full-time employees and consultant contractors, 55 of whom were located in Gabon and 8 of whom were located in Angola. The Company is not yet subject to any collective bargaining agreements, although most of the national employees in Gabon are members of the NEOP (National Organization of Petroleum Workers) union. The Company believes its relations with its employees are satisfactory.

COMPETITION

The oil and gas industry is highly competitive. Competition is particularly intense from other independent operators and from major oil and natural gas companies with respect to acquisitions of desirable oil and gas properties and contracting for drilling equipment . There is also competition for the hiring of experienced personnel. In addition, the drilling, producing, processing and marketing of oil and gas is affected by a number of factors beyond the control of the Company, including but not limited to shortages of drilling rigs, pipe and personnel, which may delay drilling, increase prices and have other adverse effects which cannot be accurately predicted.

The Companyâ€™s competition for acquisitions, exploration, development and production includes the major oil and gas companies in addition to numerous independent oil companies, individual proprietors, investors and others. Many of these competitors possess financial, technical and personnel resources substantially in excess of those available to the Company, giving those competitors an enhanced ability to evaluate and acquire desirable leases properties or prospects. The ability of the Company to generate reserves in the future will depend on its ability to select and acquire suitable producing properties and prospects for future drilling and exploration.

INSURANCE

In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating risks to which its business is exposed. The Company currently has insurance policies that include coverage for general liability (includes sudden and accidental pollution), physical damage to its oil and gas properties, operational control of offshore wells, aviation, auto liability, marine liability, workerâ€™s compensation and employerâ€™s liability, among other things. At the depths and in the areas in which the Company operates, and in light of the vertical and horizontal drilling that it undertakes, the Company typically does not encounter high pressures or extreme drilling conditions.

Currently, the Company has Operatorâ€™s Extra Expense insurance coverage up to $100 million per occurrence, which includes damage to equipment and sudden and accidental environmental liability coverage. The Companyâ€™s insurance policies contain maximum policy limits and in most cases, deductibles (generally ranging from $100,000 to $1 million) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, the Company carries $75 million of general liability insurance to cover bodily injury, property damage and pollution affecting third parties arising from its operations.

The Company requires all of its third-party contractors to sign master service agreements in which they agree to indemnify the Company for injuries and deaths of the service providerâ€™s employees as well as contractors and subcontractors hired by the service provider. Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by the Companyâ€™s employees and other contractors. Additionally, each party generally is responsible for damage to its own property.

The third-party contractors that perform hydraulic fracturing operations for the Company sign the master service agreements containing the indemnification provisions noted above. The Company does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. However, the Company believes its general liability and excess liability insurance policies would cover third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies.

The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that the Company will be able to maintain insurance in the future at rates that we consider reasonable and it may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.

ENVIRONMENTAL REGULATIONS

General

The Companyâ€™s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control in the United States, Gabon and Great Britain and will be subject to the laws and regulations of Angola and Equatorial Guinea when exploration drilling begins in those countries. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing laws, rules and regulations regulating the release of materials in the environment or otherwise relating to the protection of the environment will not have a material effect upon the Companyâ€™s capital expenditures, earnings or competitive position with respect to its existing assets and operations. The Company cannot predict what effect future regulation or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from the Companyâ€™s operations could have on its activities. In part because they are developing countries, it is unclear how quickly and to what extent Gabon, Angola or Equatorial Guinea will increase their regulation of environmental issues in the future; any significant increase in the regulation or enforcement of environmental issues by Gabon, Angola or Equatorial Guinea could have a material effect on the Company. Developing countries, in certain instances, have patterned environmental laws after those in the United States which are discussed below. However, the extent to which any environmental laws are enforced in developing countries varies significantly.

In the United States, environmental laws and regulations may require the acquisition of permits before drilling commences, the installation of pollution control equipment for our operations, special handling or disposal of materials used in our operations, or remedial measures to mitigate pollution from our operations or on the properties on which we operate. These laws and regulations may also restrict the types of substances used in our drilling operations which can be used or released into the environment or limit or prohibit drilling activities on certain lands such as wetlands or sensitive protected areas.

As a general matter, the oil and gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. The trend has been the enactment of new or more stringent requirements on the oil and gas industry. These changes result in increased operating costs, and additional changes could results in further increases in our costs for environmental compliance.

CEO BACKGROUND

Directors, Nominees and Executive Officers

The following is a brief description of the background and principal occupation of each director (including each nominee) and executive officer:
Robert L. Gerry III â€”Mr. Gerry has served as Chairman of the Board and Chief Executive Officer for VAALCO Energy, Inc. since August 1997. Mr. Gerry currently serves on the Board of Directors of Integrity Bank, an independent bank located in Houston, Texas and on the Board of Texas Childrenâ€™s Hospital. Mr. Gerry is a member of the University of Texas Press Advisory Council. Mr. Gerry also served on the Board of Directors of Plains Exploration and Production Company from 2004 through December 31, 2010. From February 1994 until August 1997, Mr. Gerry served as Vice-Chairman of Nuevo Energy Company. Prior to being appointed Vice-Chairman of Nuevo, Mr. Gerry had served as President and Chief Operating Officer of Nuevo since its formation in March 1990. Mr. Gerry served as Senior Vice President of Energy Assets International Corporation (â€śEAICâ€ť) from January 1989 until March 1990. For ten years prior to joining EAIC, Mr. Gerry was active as an independent investor concentrating on energy investments. His many years of experience provide him with the industry and leadership experience to successfully lead VAALCO and the board.

W. Russell Scheirman â€”Mr. Scheirman has served as the President of VAALCO since 1992, and as a Director since 1991. In 2008, Mr. Scheirman was named the Companyâ€™s Chief Operating Officer. From 1991 to 1992, Mr. Scheirman served as Executive Vice President of VAALCO. Prior to joining VAALCO, Mr. Scheirman was an Associate at McKinsey & Company, Inc. from 1989 to 1991, an investment banker with Copeland, Wickersham and Wiley from 1984 to 1989, and a Petroleum Reservoir Engineer for Exxon Company, U.S.A. from 1978 to 1984. Mr. Scheirman holds a B.S. (Summa Cum Laude) and M.S. in Mechanical Engineering from Duke University (1977 and 1978, respectively) and an M.B.A. from California Lutheran University (1984). His strong financial background combined with his operational experience, including over 20 years with us, provides our Board with a long-term perspective of our challenges, opportunities and operations.

Robert H. Allenâ€” Mr. Allen is the managing partner of Challenge Investment Partners, which is active in mining ventures in Canada, Mexico, Africa and South America. From 1957 to 1982 he was with Gulf Resources and Chemical Corporation, a diversified natural resource based company. During that affiliation, Mr. Allen served as Chief Executive Officer, Director and Chairman of the Board. In the past 20 years he has been instrumental in the start-up of several natural resource oriented companies, the most notable, Getty Resources Ltd., Toronto, Canada. Mr. Allen is Chairman Emeritus of the Board of Trustees of Baylor College of Medicine. He is also a member of the Advisory Board of the George Bush School of Government and Public Service, and of the Development Council of the Mays School of Business at Texas A&M University. He has served on many boards including Federal Express Corporation and Gulf Canada Resources Ltd. Most recently he served as Chairman of the Board of Gulf Indonesia Resources Ltd., and Chairman of the Board of The University of Texas Investment Management Company. He also served as Chairman of the Audit Committee of the Brown Foundation. Mr. Allen received his B.B.A. degree in 1951 from Texas A&M University. He is a certified public accountant and a member of the Texas Society of CPAâ€™s. Mr. Allen has over 50 years of experience in the oil and gas industry, with extensive experience in accounting. We believe that this industry and global experience, as well as his leadership abilities, brings valuable experience and skill to our Board of Directors.

Frederick W. Brazelton â€”Mr. Brazelton was appointed to the Board on June 27, 2008. Mr. Brazelton is the Co-Founder and President of Platform Partners, LLC, a private holding company that makes equity investments in middle-market companies. Prior to founding Platform in August 2006, Mr. Brazelton was a Partner of The CapStreet Group, LLC, an institutional private equity fund focused on investing in middle-market companies where he had worked from August 2000 until July 2006. Prior to joining CapStreet, Mr. Brazelton worked for the private equity firms of Hicks, Muse, Tate & Furst and Willis Stein & Partners after starting his career in investment banking at CS First Boston in its Natural Resources Group. Mr. Brazelton serves on the boards of directors of Encino Energy, LLC, Evergreen Environmental, LLC, Santa Barbara Tax Products Group, LLC and the Small Steps Nurturing Center. He received his BBA from the Business Honors Program at the University of Texas at Austin and his MBA from Stanford University. Mr. Brazeltonâ€™s extensive experience in private equity and finance provides a valuable resource to our Board.

Luigi P. Caflisch â€”Mr. Caflisch was appointed to the Board on April 6, 2005. He has spent over 45 years in the petroleum industry in exploration, research and development, and management. For Gulf Oil Co., he worked in the U.S.A., Europe, North Africa, Nigeria, Angola and the Far East. In 1978, Mr. Caflisch served as Vice President of Geoman, a Gulf affiliate providing technical assistance to OPEC countries, mainly in Kuwait and Venezuela. Beginning in 1982, Mr. Caflisch served as Gulfâ€™s General Manager for Exploration of the North Sea. After Chevronâ€™s acquisition of Gulf in 1984, Mr. Caflisch served as Chevronâ€™s Deputy Managing Director of Europe. Beginning in 1987, Mr. Caflisch served as Assistant to Chevronâ€™s VP of Overseas Exploration. In 1988, he became Managing Director of Africa for Chevron and in 1995 he became Managing Director of Africa and Middle East for Chevron. As a member of Chevronâ€™s Management Team, he shared responsibilities for directing worldwide Upstream operations. Since his retirement from Chevron in 1999, Mr. Caflisch has offered consulting and management assistance to a variety of companies; as a member of the board of directors or advising on target areas for exploration, acquisition or divestiture. Multilingual, he holds a Doctorate in Geology and Geophysics from the University of Milan. Mr. Caflischâ€™s technical background and his knowledge of international oil and gas operations provide a critical resource and skill set to our Board of Directors.

O. Donaldson Chapoton â€”Mr. Chapoton was appointed to the Board on February 15, 2006. He practiced law with the firm of Baker Botts, LLP from the early 1960s until 2001 specializing in income tax matters, including both transactional tax work and the legislative and regulatory matters. From 1986 to 1989, Mr. Chapoton left Baker Botts to serve as the Assistant Secretary of the Treasury for Tax Policy under President Reagan. In that role he participated in the formulating the Reagan Administrationâ€™s tax policy and presented that policy in testimony before the U.S. Congress. In 1989 he rejoined Baker Botts, LLP as the partner-in-charge of the firmâ€™s Washington office. Since retiring from Baker Botts in 2001 Mr. Chapoton has been a partner in the VMS Group, a partnership involved in investment opportunities in technology and in furnishing back office services to venture funds and partnerships. He also served for a time as a senior partner in Breen Investors, LLC, an investment advisory firm. Mr. Chapoton received his LL.B., with honors, from the University of Texas School of Law. Mr. Chapotonâ€™s legal background and experience and his knowledge of the tax law and the legislative process in Washington provides a valuable resource to our Board.

John J. Myers â€”Mr. Myers was appointed to serve on the VAALCO Energy, Inc. Board of Directors effective March 3, 2010. Mr. Myers was founder and Managing Partner for Treaty Oak Capital Management, an energy investment hedge fund based in Austin, Texas from 2002 through 2009. In 2007 Mr. Myers founded Tectonic Capital Management investment fund. Mr. Myers, a Chartered Financial Analyst, was engaged for over 20 years as an equity analyst having served with RBC Dain Rauscher Wessels, Morgan Keegan, Petrie Parkman & Co. and Southcoast Capital. Mr. Myers holds a Masters degree in Management from Northwestern University, Evanston, Illinois. He also holds a Bachelors of Science degree in Chemical Engineering from the University of Michigan, Ann Arbor, Michigan. Mr. Myerâ€™s knowledge and experience in the oil and gas business and the capital markets make him a valuable resource to our Board.

Gregory R. Hullinger â€”Mr. Hullinger joined VAALCO in October 2008 after more than 30 years of finance and accounting experience at Shell Oil Company and its parent company, Royal Dutch Shell. Notable positions held by Mr. Hullinger at Shell Oil include Controller, Treasurer, CFOâ€”Shell Deer Park Refining Company and CFOâ€”Pecten Cameroon Company (West Africa). For Royal Dutch Shell, Mr. Hullinger held the positions of International Audit Manager and as the Manager for Group Accounting, the unit responsible for the financial consolidations, results and reporting. Mr. Hullinger was twice elected Chairman of the Accounting Committee of the American Petroleum Institute. He holds a B.S. in Accounting from Louisiana State University.

Gayla M. Cutrer â€”Ms. Cutrer joined Alcorn International, Inc., predecessor to VAALCO Energy, Inc., in 1986 and served as executive support and administrative advisor for the newly founded international energy company. She was named to the board of directors on March 20, 1990 and served on the board during the Companyâ€™s transition from a privately held company to a publicly traded company. Ms. Cutrer was named Vice President and Corporate Secretary of VAALCO Energy, Inc. in 1990 and was named Executive Vice President and Corporate Secretary of VAALCO Energy, Inc. in 2011. Ms. Cutrerâ€™s previous experience in the energy industry includes positions with Cities Service International, Inc, Amoco International, Inc. and Kilroy Company of Texas.

All officers and director nominees of VAALCO are United States citizens.

MANAGEMENT DISCUSSION FROM LATEST 10K

INTRODUCTION

VAALCO owns producing properties and conducts exploration activities as an operator in Gabon, West Africa, conducts exploration activities as an operator in Angola, West Africa, conducts exploration activities as a non-operator in Equatorial Guinea, West Africa, and has conducted exploration activities as a non-operator in the British North Sea. VAALCO is the operator of unconventional and conventional resource properties in the United States located in Montana, South Dakota, and North Texas. The Company also owns minor interests in conventional production activities as a non-operator in the United States.

A significant component of the Companyâ€™s results of operations is dependent upon the difference between prices received for its offshore Gabon oil production and the costs to find and produce such oil. Oil (and gas) prices have been and are expected in the future to be volatile and subject to fluctuations based on a number of factors beyond the control of the Company. Similarly, the costs to find and produce oil and gas are largely not within the control of the Company, particularly in regard to the cost of leasing drilling rigs to drill and maintain offshore wells.

A key focus of the Company is to maintain oil production from the Etame Marin block located offshore Gabon at optimal levels within the constraints of the existing infrastructure. The Company operates the Etame, Avouma, South Tchibala and Ebouri fields on behalf of a consortium of five companies. Five subsea wells plus production from two platforms are tied back by pipelines to deliver oil and associated gas through a riser system to allow for delivery, processing, storage and ultimately offloading the oil from a leased Floating, Production, Storage and Offloading vessel (â€śFPSOâ€ť) anchored to the seabed on the block. With the FPSO limitations of approximately 25,000 BOPD and 30,000 barrels of total fluids per day, the challenge is to optimize production on both a near and long-term basis subject to investment and operational agreements between the Company and the consortium.

As part of the near-term optimization, drilling and workover campaigns are developed and executed to drill new wells, partly to replace maturing wells, and to perform workovers to replace electrical submersible pumps in existing wells. Late in 2012, a drilling and workover campaign began with the arrival of a drilling rig to conduct a six well program.

Long-term optimization progress was made in 2012 by the Company and its partners approving the construction of two additional production platforms. The two production platforms are part of the future development plans for the Etame Marin block. One platform will be located in the Etame field and the second platform will be located in-between the Southeast Etame and North Tchibala fields. Multiple wells are expected to be drilled from each of the platforms. The Company drilled a successful exploration well in the Southeast Etame area in 2010 which will be developed from the second platform. The expected cost to build and install the platforms in the 2013/2014 timeframe is $275.0 million ($77.0 million net to the Company). The cost of the wells is not included in the platform costs.

In 2012 the presence of hydrogen sulfide (H2S) from two of the three producing wells in the Ebouri field was discovered. The wells were shut-in for safety reasons resulting in a decrease of approximately 2,000 BOPD or approximately 10% of the gross daily production from the Etame Marin block. Analysis and options for re-establishing production from the impacted area was undertaken in the second half of 2012. The expected outcome is that additional capital investment will be required, which is likely to include a new platform-type structure with H2S processing capability, and new wells to re-establish production from the impacted area. The design, cost projections and final investment decisions by the Company and its partners are expected to be made in 2013. Re-establishing production from the area impacted by H2S is expected in the first half of 2016.

Besides the offshore Etame Marin block in Gabon, the Company operates the Mutamba Iroru block located onshore Gabon. The Company has a 50% working interest in the block. After drilling two unsuccessful exploration wells on the block in 2009, the Company entered into an agreement with Total Gabon to continue the exploration activities. Following seismic reprocessing, a discovery well was drilled in 2012. The plan of development will be the next step undertaken which will be the focus of 2013 for this property. Development of the onshore block is expected to capitalize on synergies such as office space, warehouse and open yard space and experienced personnel from our operating base in Port Gentil, Gabon.

An important item for the Company is growth in terms of establishing meaningful production operations in more than one country. The Company routinely evaluates working interest opportunities primarily in the West African geographic area where the Company has significant expertise and where the base of the foreign operations is located. During 2012, the Company identified an opportunity to purchase a working interest in Block P, Equatorial Guinea. In November 2012, the Company completed the acquisition of a 31% working interest in the block at a cost of $10.0 million. Prior to the Companyâ€™s acquisition, two recent oil discoveries had been made on the block, and there is exploration potential on other areas of the block. The Company expects to participate in the drilling of two exploration wells in the 2013/2014 time horizon.

With a focus on diversification and utilizing available capital resources, the Company invested in three non-conventional acreage acquisitions in Texas and Montana in late 2010 and in 2011. Two wells have been drilled on the Texas acreage and brought on production. The second well began production in March 2012. In Montana, four unsuccessful exploration wells were drilled on the two properties in 2012. The outcome of the fifth well drilled in Montana in 2012 will be determined in the first half of 2013. With the unsuccessful results in Montana and increasing opportunities available to the Company internationally, the Company is not expecting to focus on further domestic property acquisitions in the near term.

CRITICAL ACCOUNTING POLICIES

The following describes the critical accounting policies used by the Company in reporting its financial condition and results of operations. In some cases, accounting standards allow more than one alternative accounting method for reporting, such is the case with accounting for oil and gas activities described below. In those cases, the Companyâ€™s reported results of operations would be different should it employ an alternative accounting method.

Successful Efforts Method of Accounting for Oil and Gas activities

The SEC prescribes in Regulation S-X the financial accounting and reporting standards for companies engaged in oil and gas producing activities. Two methods are prescribed: the successful efforts method and the full cost method. Like many other oil and gas companies, the Company has chosen to follow the successful efforts method. Management believes that this method is preferable, as the Company has focused on exploration activities wherein there is risk associated with future success and as such earnings are best represented by attachment to the drilling operations of the Company. Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Other exploration costs, including geological and geophysical expenses applicable to undeveloped leasehold, leasehold expiration costs and delay rentals are expensed as incurred.

In accordance with the successful efforts method of accounting, the Company reviews proved oil and gas properties for indications of impairment whenever events or circumstances indicate that the carrying value of its oil and gas properties may not be recoverable. When it is determined that an oil and gas propertyâ€™s estimated future net cash flows will not be sufficient to recover its carrying amount, an impairment charge must be recorded to reduce the carrying amount of the asset to its estimated fair value. This may occur if a field contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field.

Impairment of Unproved Property

The Company evaluates its unproved properties for impairment on a property-by-property basis. The majority of the Companyâ€™s unproved property consists of acquisition costs related to its undeveloped acreage in Angola, Equatorial Guinea and in the United States. On at least a quarterly basis, management reviews the unproved property for indicators of impairment based on the Companyâ€™s current exploration plans with consideration given to results of any drilling and seismic activity during the period and known information regarding exploration activity by other companies on adjacent blocks. See Item 2â€”Properties and Note 6 to the consolidated financial statements for further information on the Companyâ€™s exploration plans in Angola and Equatorial Guinea.

In Angola, any adverse developments related to the Companyâ€™s ability to further extend the drilling obligation date, if necessary, could result in an impairment of the Companyâ€™s unproved properties and other assets with a carrying value of approximately $11.0 million.

In the United States, the Company recorded an impairment loss of $7.6 million in 2012 to write down the value of its unproved property, due to its unsuccessful exploration activities ($3.8 million in Roosevelt County, Montana, $2.3 million in Sheridan County, Montana, and $1.5 million in Harding County, South Dakota).

Asset Retirement Obligations (â€śAROâ€ť)

The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. The Companyâ€™s removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of offshore oil and gas platforms, and capping pipelines. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.

ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with The Companyâ€™s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Net cash provided by operating activities for 2012 was $94.0 million, as compared to $89.6 million in 2011 and $45.5 million in 2010. The increase in cash provided by operating activities in 2012 versus 2011 was primarily due to both an increase in non-cash adjustments to net income of $31.3 million and an $8.3 million positive variance in changes in operating assets and liabilities, partially offset by a $35.2 million reduction in net income. The increase in cash provided by operating activities in 2011 versus 2010 was primarily due to a $32.5 million positive variance in changes in operating assets and liabilities and increased non-cash adjustments to net income of $13.4 million.

Net cash used in investing activities in 2012 was $71.8 million, compared to net cash used in investing activities for 2011 of $28.4 million and net cash used in investing activities in 2009 of $39.4 million. In 2012, the Company paid $71.9 million for capital expenditures, partly offset by a $0.1 million release of restricted cash. The Company paid $32.0 million for capital expenditures in 2011, partially offset by a $3.6 million release of restricted cash. In 2010, the Company paid $40.0 million for capital expenditures, partially offset by a $0.6 million release of restricted cash.

In 2012, cash used in financing activities was $28.5 million consisting of an acquisition of a noncontrolling interest for $ 26.2 million and distributions to a noncontrolling interest owner of $5.6 million, partially offset by proceeds from the issuance of common stock upon the exercise of options of $3.3 million. In 2011, cash used in financing activities was $5.3 million consisting of distributions to a noncontrolling interest owner of $7.2 million partially offset by proceeds from the issuance of common stock upon the exercise of options of $1.9 million. In 2010, cash used in financing activities was $5.5 million, consisting primarily of distributions to a noncontrolling interest owner of $6.0 million partially offset by proceeds from the issuance of common stock upon the exercise of options of $0.5 million.

In recent history, the Companyâ€™s primary source of capital resources has been from cash flows from operations. On December 31, 2012, the Company had cash balances of $130.8 million and restricted cash of $12.1 million. The Company believes that these cash balances combined with cash flow from operations will be sufficient to fund the Companyâ€™s 2013 capital expenditure budget, which is expected to total approximately $75.0 million to: further develop the Etame Marin block offshore Gabon with a three well drilling program; to fund construction costs for two platforms being built for the Etame Marin block; potential exploration drilling of one well on Block 5 in Angola or Block P in Equatorial Guinea; final expenditures for an unsuccessful exploration well in the Salt Lake area in Sheridan County, Montana; completion of an exploration well in the East Poplar unit in Roosevelt County, Montana; and the drilling of an exploration well in Harding County, South Dakota.

The Company invests cash not required for immediate operational and capital expenditure needs in short-term bankers acceptance and money market instruments primarily with JPMorgan Chase & Co. The Company does not invest in the asset-backed commercial paper market which has been subject to a liquidity crisis over the last few years. As operator of the Etame, Avouma, South Tchibala and Ebouri producing fields, and the Southeast Etame and North Tchibala fieds currently being developed, the Company enters into project related activities on behalf of its working interest partners. The Company generally obtains advances from its partners prior to significant funding commitments.

Capital Expenditures

In 2012, the Company invested $46.4 million in property and equipment additions (including amounts carried in accounts payable and excluding exploration dry hole costs), primarily associated with $13.6 million to drill and complete the second Granite Wash formation well in the United States and one exploratory well in Montana, $16.7 million for platform modifications and production facilities offshore Gabon, $10.0 million to acquire mineral interests in Block P offshore Equatorial Guinea, and $6.0 million to drill an exploratory well onshore Gabon. In 2011, the Company invested $33.0 million in property and equipment additions, primarily associated with $9.5 million to acquire leases in the United States, $14.9 million to drill three wells in the United States, and $7.4 million primarily for offshore platform modifications and production facilities in Gabon. During 2010, the Company invested $40.5 million in property and equipment additions, primarily associated with the drilling of three development wells in the Etame Marin block offshore Gabon totaling $29.3 million. In addition, in 2010, one successful exploration well was drilled in the Southeast Etame area of the Etame Marin block at a cost of $8.0 million, and the Company invested in a Granite Wash formation lease in Texas ($2.2 million) and a second extension of the Mutamba Iroru block onshore Gabon ($1.2 million).

Oil and Gas Exploration Costs

As described above, the Company uses the â€śsuccessful effortsâ€ť method of accounting for its oil and gas exploration and development costs. All expenditures related to exploration, with the exception of costs of drilling exploration wells, are charged as an expense when incurred. The costs of exploration wells are capitalized pending determination of whether commercially producible oil and gas reserves have been discovered. If the determination is made that a well did not encounter potentially economic oil and gas quantities, the well costs are charged as an expense. Exploration expense in 2012 was $41.0 million, including a $37.3 million in write-off costs related to five unsuccessful exploration wells in the United States, and $0.9 million spent for various geological and leasehold related activities in the United States. Additionally, in 2012 the Company incurred exploration expenditures of $2.8 million internationally for various geological and geophysical activities. In 2011, the Company incurred $5.7 million in exploration expense, including $2.0 million spent in the United States and Canada (primarily exploration well costs), $1.9 million offshore Gabon (primarily seismic acquisition costs), $0.8 million onshore Gabon (seismic reprocessing costs), $0.4 million in the United Kingdom (residual exploration well costs), and $0.6 million in Angola (exploration well preparation costs). In 2010, the Company incurred $6.8 million in exploration expense, including $2.6 million on the Omangou unsuccessful exploration well offshore Gabon, $1.4 million for seismic costs in the Etame Marin block offshore Gabon, onshore Gabon exploration expense of $0.7 million, and $0.9 million in Angola.

1.
The Company is guarantor of a lease for the FPSO utilized in Gabon, which has remaining obligations of $205.5 million. The Companyâ€™s share of these payments is included in the table above. Approximately 72% of the payment is co-guaranteed by the Companyâ€™s partners in Gabon. In addition to the FPSO amounts, the schedule includes the Companyâ€™s share of its other lease obligations.

In addition to the contractual obligations described above, the Company entered into a sixth exploration period extension during 2009 and is required to spend $5.3 million for its share of two exploration wells and acquire/process 150 square kilometers of 3-D seismic on the Etame Marin block by July 2014. One of the two exploration commitment wells was drilled in 2010 on the Omangou prospect at a cost of $8.6 million ($2.6 million net to the Company). The seismic obligation was met with the acquisition of 223 square kilometers of 3-D seismic in 2012. The remaining obligation is the drilling of one exploration well which is scheduled for drilling in mid-2013.

As part of securing the second ten year production license with the government of Gabon, the Company agreed in principle to a cash funding arrangement for the eventual abandonment of the offshore wells, platforms and facilities. The agreement is not yet finalized, but calls for annual funding for the next seven years at 12.14% of the abandonment estimate and 5.0% for the last three years of the production license. The amounts paid will be reimbursed through the cost account and are non-refundable to the Company. The funding is expected to begin in 2013 after the agreement is finalized. The abandonment estimate for this purpose is estimated to be approximately $9.7 million net to the Company on an undiscounted basis. As in prior periods, the obligation for abandonment of the Gabon offshore facilities is included in the asset retirement obligation shown on the Companyâ€™s balance sheet.

The Company also entered into the second exploration period for the Mutamba Iroru block which requires the Company to reprocess 400 kilometers of 2-D seismic and drill one exploration well by May 2012. The seismic reprocessing work was completed in 2012. The exploration well was drilled in 2012 resulting in a discovery. A plan of development is expected to be completed for the Nâ€™Gongui field and submitted to the government of Gabon in 2013. In return for funding 75% of the work commitment (seismic reprocessing and exploration well costs), Total Gabon earned a 50% interest on the permit.

In 2010, the exploration permit was successfully extended until May 2012 and an application for a further nine-month extension was made in early 2012. In a letter agreement from the government of Gabon, the terms of the extension to March 2013 were agreed upon, yet the extension amendment was not executed by the government of Gabon. The Company and Total are working with the Gabon government in 2013 to finalize the extension and to obtain a further exploration extension. However, the Company can provide no assurances that such a request will be granted. The Company believes the discovery area is not impacted by the uncertainty of the extension agreement as the well was drilled during the contracted period and application of the discovery was timely made to the government of Gabon.

In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola. The four year primary term with an optional three year extension awards the Company exploration rights to 1.4 million acres offshore central Angola. The Companyâ€™s working interest is 40%. Additionally, the Company is required to carry the Angolan national oil company, Sonangol P&P, for 10% of the work program. During the first four years of the contract the Company was required to acquire and process 1,000 square kilometers of 3-D seismic data, drill two exploration wells and expend a minimum of $29.5 million ($14.8 million net to the Company). The Company fulfilled its seismic obligation when it acquired 1,175 square kilometers of 3-D seismic data at a cost of $7.5 million ($3.75 million net to the Company) in January 2007 and 524 square kilometers of 3-D seismic data during the fourth quarter of 2008 at a cost of $6.0 million ($3.0 million net to the Company).

The government-assigned working interest partner was delinquent paying their share of the costs several times in 2009 and consequently was placed in a default position. By a governmental decree dated December 1, 2010, the former partner was removed from the production sharing contract, and a one year time extension was granted for drilling the two exploration commitment wells. Following the decree, the Company and the government of Angola have been working together to obtain a replacement partner. In early 2012, the Angolan government granted a further one year extension to November 30, 2012 for drilling the two exploration commitment wells in accordance with the production sharing contract. In July 2012, the Angolan government granted an additional two year extension until November 30, 2014 to drill the two exploration commitment wells.

In the first quarter of 2012, the Company provided the Angolan government with a written offer that would allow the Company to proceed with exploration activities without obtaining a new partner, subject to certain criteria including changes to the work commitment and working interest percentages. In the second quarter of 2012, the Company identified a potential partner to acquire the available 40% working interest and submitted the name of the interested party to the Angolan government for approval. In November 2012, the government advised the Company that it has entered into negotiations with the potential partner. The Company met with the Angolan government in January 2013 and learned the negotiations are still underway.

The remaining obligation is a two well exploration commitment. Each well is subject to a $5.0 million penalty ($10.0 million in aggregate for both wells) if not drilled during the contract term. The $10.0 million is currently recorded as restricted cash and is held at a financial institution located in the United States.

Because of the continuing uncertainty with the Angolan government approving a replacement partner, the Company has recorded a full allowance totaling $6.0 million as of December 31, 2012, against the accounts receivable from partners for the amounts owed to the Company above its 40% working interest plus the 10% carried interest. The allowance recorded in the twelve months ended December 31, 2012 totaled $1.6 million with the remainder having been recorded in 2011. The Company expects the gross receivable to be paid to the Company if a new partner in the block is approved.

The Company is carrying $10.4 million of asset retirement obligations as of December 31, 2012, representing the present value of these obligations as of that date.

RESULTS OF OPERATIONS

Year Ended December 31, 2012 Compared to Years Ended December 31, 2011 and 2010

Total Revenues

Total oil and gas sales for 2012 were $195.3 million as compared to $210.4 million and $134.5 million for 2011 and 2010, respectively.

Oil Revenues

Gabon

Crude oil revenues for 2012 were $192.5 million, as compared to revenues of $208.8 million and $134.5 million for 2011 and 2010 respectively. In 2012, the Company sold approximately 1,730,000 net barrels of oil at an average price of $111.24/Bbl. In 2011, the Company sold approximately 1,864,000 net barrels of oil at an average price of $111.98. In 2010, the Company sold approximately 1,714,000 net barrels of oil at an average price of $78.38/Bbl.

United States

Condensate sales from the Granite Wash formation wells, located in Hemphill County, Texas for the year 2012 were $0.8 million, resulting from the sale of approximately 10,000 net barrels of oil condensate at an average price of $81.68/Bbl. For the same period in 2011, condensate sales from the Granite Wash formation wells were $0.3 million, resulting from the sale of approximately 4,000 net barrels of oil condensate at an average price of $79.71/Bbl. There were no condensate sales from the Granite Wash formation wells in 2010.

Natural Gas Revenues

United States

Natural gas revenues including revenues from natural gas liquids for the year 2012 were $1.9 million compared to $1.3 million and $0.1 million for the years 2011 and 2010 respectively. In 2012, natural gas sales were 532 MMcf at an average price of $3.66/Mcf. In 2011, natural gas sales including revenues from natural gas liquids were 255 MMcf at an average price of $5.23/Mcf. In 2010, natural gas sales including revenues from natural gas liquids were 14 MMcf at an average price of $4.79/Mcf.

Operating Costs and Expenses

Production expense for 2012 was $26.7 million as compared to $26.7 million and $22.1 million for 2011 and 2010, respectively. In 2012, the Company incurred lower Domestic Market Obligation payments to the Republic of Gabon of $1.8 million, and lower fuel expense of $0.7 million, which were partially offset by higher FPSO facility costs of $2.5 million as a result of a contract extension and revision. Production expense was higher in 2011 as compared to 2010 as the result of higher sales volumes and higher Domestic Market Obligation payments to the Republic of Gabon. Any production expenses associated with unsold crude oil inventory are capitalized.

Exploration expense in 2012 was $41.0 million, including a $37.3 million in write-off costs related to five unsuccessful exploration wells in the United States, and $0.9 million spent for various geological and leasehold related activities in the United States. Additionally, in 2012 the Company incurred exploration expenditures of $2.8 million internationally for various geological and geophysical activities. In 2011, the Company incurred $5.7 million in exploration expense, including $2.0 million spent in the United States and Canada (primarily exploration well costs), $1.9 million offshore Gabon (primarily seismic acquisition costs), $0.8 million onshore Gabon (seismic reprocessing costs), $0.4 million in the United Kingdom (residual exploration well costs), and $0.6 million in Angola (exploration well preparation costs). In 2010, exploration expense was $6.8 million, primarily comprised of $2.6 million on the Omangou unsuccessful exploration well offshore Gabon, $1.4 million for seismic costs in the Etame Marin block offshore Gabon, onshore Gabon exploration expense of $0.7 million, and $0.9 million in Angola primarily for geotechnical studies.

Depreciation, depletion and amortization expense was $19.9 million in 2012 as compared to $25.6 million and $20.0 million for 2011 and 2010, respectively. Depletion, depreciation and amortization expense decreased in 2012 versus 2011 due to both lower sales volumes and lower depletion rates in 2012. The 2011 depletion, depreciation and amortization rates increased in 2011 versus 2010 due to both higher sales volumes and higher depletion rates. The 2012 depletion rates for the Ebouri field averaged $21.14 per Bbl, Avouma and South Tchibala fields averaged $4.11 per Bbl, and the Etame field averaged $4.64 per Bbl. Depletion rates for the Granite Wash wells averaged $6.16 per Mcf.

General and administrative expense for 2012 was $11.8 million as compared to $10.4 million and $7.4 million for 2011 and 2010, respectively. The increase in general and administrative expenses for 2012 versus 2011 was primarily due to higher administrative costs related to the Companyâ€™s staffing expansion to accommodate the increased exploration and development activities. The increase in general and administrative expense for 2011 versus 2010 was primarily due to $3.7 million lower overhead reimbursement associated with lower capital expenditures offshore Gabon.

During 2012, the Company incurred $2.4 million of non-cash stock based compensation expense, as compared to $2.2 million and $1.8 million for 2011 and 2010, respectively. In each of the three years, the Company benefited from overhead reimbursement associated with production and development operations on the Etame Marin block.

During 2012 and 2011, the Company recorded bad debt provisions of $1.6 million and $4.4 million, respectively, related to the uncertainty in collecting its joint venture receivable in Angola.

During 2012 and 2011, the Company recorded impairment losses of $7.6 million and $5.0 million, respectively, on its proved property, to write down its investment in the Granite Wash formation of North Texas to its fair value.

Operating Income

Operating income for 2012 was $86.6 million as compared to $132.6 million and $78.1 million for 2011 and 2010, respectively. The lower operating income for 2012 versus 2011 is primarily attributable to lower sales volumes and higher exploration costs resulting from charges recorded to write off the companyâ€™s unsuccessful efforts in the United States. The higher operating income in 2011 versus 2010 was attributable to both higher sales volumes and higher average crude sales prices of $111.92 per Bbl, an increase of $33.55 per Bbl over 2010.

Other Income (Expense)

Interest income for 2012 was $0.1 million compared to $0.2 million and $0.2 million for each of the years 2011 and 2010. All 2012, 2011, and 2010 amounts represent interest earned and accrued on cash balances and restricted cash.

During 2012, other income was $0.4 million as compared to other income of $1.3 million for 2011 and other expense of $0.6 million for 2010. Other income and expense is primarily the result of foreign currency transaction gains and losses from the Companyâ€™s foreign operations.

Income Taxes

In 2012, the Company incurred $81.8 million in income taxes as compared to $93.5 million and $35.3 million for 2011 and 2010, respectively. All income tax expenses were associated with the Etame Marin block production, and were incurred in Gabon. The lower income tax expense for 2012 versus 2011 was primarily the result of lower sales volumes, resulting in lower profit oil barrels subject to taxes. The higher income tax expense in Gabon in 2011 versus 2010 is a function of higher sales volumes, significantly higher oil prices, and modest costs incurred, resulting in higher profit oil barrels subject to taxes. After deducting royalty and cost oil, the remaining barrels are profit oil barrels which bear income tax.

Net Income

Net income for 2012 was $5.3 million compared to $40.6 million and $42.4 million for 2011 and 2010, respectively. The decrease in net income in 2012 versus 2011 is the result of lower sales volumes and higher exploration costs, partially offset by lower income taxes. The decrease in net income in 2011 versus 2010, despite higher sales volumes and average oil prices, was due to higher income taxes and one-time charges for bad debt expense and impairment losses.

Income attributable to the noncontrolling interest in the Gabon subsidiary was $4.7 million for 2012 prior to acquisition, as compared to $6.4 million and $5.0 million for 2011, and 2010, respectively. The noncontrolling interest was acquired by the Company at a cost of $26.2 million effective October 1, 2012.

NEW ACCOUNTING PRONOUNCEMENTS

None.

OFF BALANCE SHEET ARRANGEMENTS

For a discussion of off balance sheet arrangements associated with the guarantee by the Company of the charter payments for the FPSO located in Gabon, see Note 6 to the consolidated financial statements.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

INTRODUCTION

VAALCO owns producing properties and conducts exploration activities as an operator in Gabon, West Africa, conducts exploration activities as an operator in Angola, West Africa, and conducts exploration activities as a non-operator in Equatorial Guinea, West Africa. VAALCO is the operator of unconventional and conventional resource properties in the United States located in Montana and North Texas. The Company also owns minor interests in conventional production activities as a non-operator in the United States.

A significant component of the Companyâ€™s results of operations is dependent upon the difference between prices received for its offshore Gabon oil production and the costs to find and produce such oil. Oil (and gas) prices have been and are expected in the future to be volatile and subject to fluctuations based on a number of factors beyond the control of the Company. Similarly, certain costs to find and produce oil and gas are largely not within the control of the Company, particularly in regard to the cost of leasing drilling rigs to drill and maintain offshore wells.

Offshore Gabon

The Companyâ€™s primary source of revenue is from the Etame Production Sharing Contract related to the Etame Marin block located offshore the Republic of Gabon. VAALCO operates the Etame Marin block on behalf of a consortium of five. VAALCO owns a 30.35% interest in the exploration acreage within the Etame Marin block. The Company owns a 28.1% interest in the development areas in and surrounding the Etame, Avouma, South Tchibala, and Ebouri fields, each of which is located on the Etame Marin block. The development areas were subject to a 7.5% back-in by the Government of Gabon, which occurred for these fields after their successful development. The Southeast Etame and North Tchibala fields, each of which is also located on the Etame Marine block, are in the process of being developed and will also be subject to a 7.5% back-in by the Government of Gabon.

A key focus of the Company is to maintain oil production from the Etame Marin block at optimal levels within the constraints of the existing infrastructure. Five subsea wells plus production from two platforms are tied back by pipelines to deliver oil and associated gas through a riser system to allow for delivery, processing, storage and ultimately offloading the oil from a leased Floating, Production, Storage and Offloading vessel (â€śFPSOâ€ť) anchored to the seabed on the block. With the FPSO limitations of approximately 25,000 BOPD and 30,000 barrels of total fluids per day, the challenge is to optimize production on both a near and long-term basis subject to investment and operational agreements between the Company and the consortium. The Company produces from the Etame, Avouma, South Tchibala and Ebouri fields on the block. During the three and nine months ending September 30, 2013, these fields produced approximately 1.6 million Bbls (0.4 million Bbls net to the Company) and 4.6 million Bbls (1.3 million Bbls net to the Company), respectively. The Companyâ€™s share of barrels sold reflects an allocation of cost oil and profit oil, and a reduction for royalty of 13%.

During 2011 and 2012, the Company invested in platform modifications to both the Ebouri and Avouma offshore platforms to accommodate the drilling of additional wells in addition to upgrading the electrical and power generation systems on both platforms. A new personnel accommodation module was installed during 2012 at the Avouma platform. Water knock-out facilities at the Avouma platform began operations in the third quarter of 2013.

Late in 2012, the Company commenced work on a drilling and recompletion campaign with the arrival of a drilling rig to conduct a six well program, with an option to extend the program to a total of eight wells. The six well program included three well recompletions to replace electrical submersible pumps, a development well that was successfully drilled and put on production in the Avouma field in April 2013, an unsuccessful exploration appraisal well drilled in the Ebouri field in the second quarter of 2013, and an unsuccessful exploration well drilled on the Ovoka prospect in the third quarter of 2013. The Company and its partners exercised the rig option in the third quarter of 2013 for the additional two wells in the program. The rig is scheduled to commence the two well program in late-December 2013, which will be comprised of an exploration well in the Dimba prospect and a well recompletion in the Avouma field to replace electrical submersible pumps.

Long-term optimization progress was made in 2012 by the Company and its partners approving the construction of two additional production platforms. The two production platforms are part of the future development plans for the Etame Marin block. One platform will be located in the Etame field and the second platform will be located in-between the Southeast Etame and North Tchibala fields. Multiple wells are expected to be drilled from each of the platforms as part of the future development plans for the Etame Marin block. The Company drilled a successful exploration well in the Southeast Etame area in 2010. The Southeast Etame discovery will be developed from the second platform. The expected cost to build and install the platforms in the 2013/2014 timeframe is $325.0 million ($91.0 million net to the Company). The cost of the wells is not included in the platform costs. Constructions of the two production platforms began in the first quarter of 2013 and are scheduled for installation in 2014. The Companyâ€™s share of the total construction costs of the two platforms to-date is $37.8 million, of which $30.4 million was spent in the nine months ended September 30, 2013.

In 2012, the presence of hydrogen sulfide (H2S) from two of the three producing wells in the Ebouri field was discovered. The wells were shut-in for safety reasons resulting in a decrease of approximately 2,000 BOPD or approximately 10% of the gross daily production from the Etame Marin block. In the second quarter of 2013, the Company spent $0.5 million ($0.2 million net to the Company) to temporarily suspend the two affected wells. Analysis and options for re-establishing production from the impacted area began in the second half of 2012 and has continued through the third quarter of 2013. Engineering and flow assurance work will continue through at least the end of 2013 to further develop solution options. The expected outcome is that additional capital investment will be required, which is likely to include a new platform-type structure with H2S processing capability, recompletion of the shut-in wells and potentially additional new wells to re-establish and maximize production from the impacted area. The design, cost projections and final investment decisions by the Company and its partners are expected to be made in the first half of 2014. Re-establishing production from the area impacted by H2S is expected in the first half of 2016.

Onshore Gabon

Besides the offshore Etame Marin block in Gabon, the Company operates the Mutamba Iroru block located onshore near the coast in central Gabon. The Mutamba Iroru block contains an exploration area of approximately 270,000 acres. The Company currently has a 50% working interest in the block. The Company entered into an agreement with Total Gabon in 2010 to continue the exploration activities. Under the terms of the agreement, the Company and Total Gabon committed to reprocess 400 kilometers of 2-D seismic data and drill one exploration well. The seismic reprocessing work was completed in 2012.
The Nâ€™Gongui 2 exploration well was drilled in 2012 resulting in a discovery at a cost of $19.7 million ($8.8 million net to the Company). Application of the discovery was made timely to the government of Gabon and the issuance of the development permit is pending finalization of financial terms. Development of the onshore block is expected to capitalize on synergies such as office space, warehouse and open yard space and experienced personnel from our operating base in Port Gentil, Gabon.

In 2010, the exploration permit was successfully extended until May 2012 and an application for a further nine-month extension was made in early 2012. The Company and Total Gabon are working with the Gabon government to finalize the extension and to obtain a further exploration extension. The negotiations have continued without reaching agreement. The government of Gabon has proposed new financial and other terms which have not been accepted by the Company. The Company can provide no assurances that an agreement for an extension of the exploration permit will be reached with the government of Gabon.

Offshore Angola

In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola. The four year primary term with an optional three year extension awards the Company exploration rights to 1.4 million acres offshore central Angola. The Companyâ€™s working interest is 40%.
By a governmental decree, dated December 1, 2010, the former partner was removed from the production sharing contract. Following the decree, the Company and the government of Angola have been working together to obtain a replacement partner. Additional time extensions have been granted by the Angolan government to drill the two exploration commitment wells, the latest extension providing until November 30, 2014 to drill.

In the second quarter of 2012, the Company identified a potential partner to acquire the available 40% working interest and submitted the name of the interested party to the Angolan government for approval. In July 2013, the Angolan government informed the Company that it should first proceed to acquire the available working interest per the provisions of the Joint Operating Agreement and then enter into a farm-out agreement with the potential partner. After requesting the assignment of the available working interest, the Company received correspondence from the Angolan government in November 2013 whereby they notified the Company of their plan to effect the working interest assignment directly to a third party. The Company cannot provide a time estimate for completing the working interest assignment, or whether the assignment will occur at all, as it involves actions by the Angolan government. After the assignment of the 40% is completed, the Company intends to commence drilling two exploration wells as soon as practical.

Due to the continuing circumstances regarding the available 40% working interest, the Company has recorded a full allowance totaling $7.4 million as of September 30, 2013, against the accounts receivable from partners for the amounts owed to the Company above its 40% working interest plus the 10% carried interest. The allowance recorded in the three and nine months ended September 30, 2013 totaled $0.1 million and $1.3 million, respectively. The farm-out agreement provides for the Company to be reimbursed for the gross receivable amount. The timing of this event cannot be reasonably predicted at the present time.

Offshore Equatorial Guinea

An important goal for the Company is establishing meaningful production operations in more than one country. The Company routinely evaluates working interest opportunities primarily in the West African geographic area where the Company has significant expertise and where the base of the foreign operations is located.

During 2012, the Company identified an opportunity to purchase a working interest in Block P, Equatorial Guinea. In November 2012, the Company completed the acquisition of a 31% working interest in the block at a cost of $10.0 million. Prior to the Companyâ€™s acquisition, two oil discoveries had been made on the block, and the Company believes that there is exploration potential on other areas of the block.

The Company and its partners are proceeding with plans to drill two exploration wells in 2014.

Onshore Domesticâ€”Texas

The Company acquired a 640 acre lease, the Hefley field, in the Granite Wash formation in North Texas in December 2010 and a 480 acre lease in the same formation in July 2011. Two wells have been drilled on the Hefley lease acreage and brought on production. The second well began production in March 2012. During the three months ended September 30, 2013, the two wells produced approximately 1,600 Bbls of oil and 74 million cubic feet of gas net to the Company after deduction of royalty and severance taxes. During the nine months ended September 30, 2013, the two wells produced approximately 4,000 Bbls of oil and 257 million cubic feet of gas net to the Company after deduction of royalty and severance taxes The Hefley field acreage is held by production. In the second quarter 2013, the Company decided it was unlikely to conduct further exploratory activities on the unevaluated portion of the Hefley field. Accordingly, the Company charged $0.7 million to exploration expense, which represented the remaining cost of the unevaluated Hefley leasehold.

The expiration date of the primary term of the 480 acre Granite Wash lease is August 2014. In the third quarter of 2013, the Company decided to not proceed with drilling wells on this acreage and has recognized the leasehold investment as an asset held for sale. Based on recent market transactions for leases in the area, the Company incurred exploration expense of $1.6 million to write-down the investment to its market value of $0.2 million.

Onshore Domesticâ€”Montana

In May 2011, the Company acquired a 70% working interest in approximately 5,200 acres (3,640 net acres) in Sheridan County, Montana in the Middle Bakken formation. The Company drilled two wells on this acreage in 2012. After completion testing beginning in the fourth quarter of 2012 using electrical submersible pumps (ESPâ€™s), both of the wells drilled were determined to be unsuccessful as the operating and water disposal costs exceeded the value of the gas and condensate produced from the wells. Dry-hole cost and leasehold impairment totaling $15.7 million was recognized for these two wells ($14.2 million in the fourth quarter of 2012 and $1.5 million in the first quarter 2013). As the Company does not intend to drill any further wells on this acreage expiring, for the most part, within a year, the remaining leasehold cost of $0.5 million was charged to exploration expense in the third quarter of 2013.
In September 2011, the Company acquired a 65% working interest in approximately 22,000 gross acres (14,300 net acres) covering the Middle Bakken and deeper formations in the East Poplar unit and the Northwest Poplar field in Roosevelt County, Montana. Pursuant to the terms of the acquisition, the Company was required to drill three wells at its sole cost, one of which was required to be drilled by September 1, 2012 and the remaining two wells were required to be drilled by the end of 2012. A vertical exploration well, which met the time requirement for drilling the first well, was spudded in December 2011 to evaluate the formations. The second exploration well was drilled and completed in the Bakken/Three Forks formations. Both of these wells were unsuccessful efforts, resulting in dry-hole costs and leasehold impairment totaling $18.4 million recorded in the fourth quarter of 2012. The third obligatory well, which was drilled in the fourth quarter of 2012 at a cost of $3.0 million, was charged to dry-hole expense in the third quarter of 2013. Leasehold cost of $1.3 million remains capitalized for this acreage in Roosevelt County, Montana.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows
Net cash provided by operating activities for the nine months ended September 30, 2013 was $36.8 million, as compared to net cash provided by operating activities of $44.8 million for the nine months ended September 30, 2012. The $8.0 million decrease in cash from operations for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 was primarily due to a $7.6 million reduction in net income, a $5.7 million negative variance in changes in operating assets and liabilities, partially offset by a $5.3 million positive variance in non-cash adjustments. The $5.7 million negative variance in changes in operating assets and liabilities was primarily due to a higher underpaid position from the Companyâ€™s joint venture partners.
Net cash used in investing activities for the nine months ended September 30, 2013 was $57.0 million, compared to net cash used in investing activities for the nine months ended September 30, 2012 of $43.5 million. For the nine months ended September 30, 2013 the Company paid $56.1 million for capital expenditures, and added $0.9 million to its restricted cash balance in Gabon. For the nine months ended September 30, 2012 the Company paid $43.5 million for capital expenditures, which was partially offset by a $0.1 million release of restricted cash in Gabon.

For the nine months ended September 30, 2013, net cash used in financing activities was $10.1 million consisting of treasury stock purchases of $10.7 million, partially offset by the receipt of $0.6 million in proceeds from the issuance of common stock upon the exercise of stock options. For the nine months ended September 30, 2012, cash used in financing activities was $2.2 million consisting of distributions to a noncontrolling interest of $5.6 million, which was partially offset by the receipt of $3.4 million in proceeds from the issuance of common stock upon the exercise of stock options.

Capital Expenditures

During the nine months ended September 30, 2013, the Company incurred $44.6 million of net property and equipment additions, primarily associated with $30.4 million for the construction of two new platforms offshore Gabon, $10.9 million for two development wells offshore Gabon, $1.8 million for production facilities improvements offshore Gabon, and $1.0 million for the onshore Gabon exploratory well. During the fourth quarter of 2013, the Company anticipates its share of capital expenditures will approximate $17.0 million primarily associated with the offshore Gabon block for the construction of two platforms and the drilling of one exploration well.

Oil and Gas Exploration Costs

The Company uses the â€śsuccessful effortsâ€ť method of accounting for its oil and gas exploration and development costs. All expenditures related to exploration, with the exception of costs of drilling exploratory wells, are charged as an expense when incurred. The costs of exploratory wells are capitalized pending determination of whether commercially producible oil and natural gas reserves have been discovered. If the determination is made that a well did not encounter potentially economic oil and gas quantities, the well costs are charged as an expense.

For the nine months ended September 30, 2013, exploration expense was $21.5 million, primarily comprised of $11.2 million related to the Companyâ€™s unsuccessful exploration activities in the United States, $9.0 million of dry-hole costs related to two unsuccessful offshore Gabon exploration wells. Additional exploration costs incurred in the nine months ended September 30, 2013 were $0.5 million onshore Gabon, $0.5 million offshore Gabon, and $0.2 million in Equatorial Guinea.

For the nine months ended September 30, 2012, exploration expense was $5.0 million, consisting primarily of a $2.9 million dry-hole charge to write-off the exploratory costs associated with drilling and testing of several intervals below the Bakken/Three Forks formation on the EPU-120 well drilled in the East Poplar Dome field in Montana. Additional exploratory costs incurred in the nine months ended September 30, 2012 were $0.7 million for North America, $0.4 million onshore Gabon, $0.6 million offshore Gabon, $0.2 million in Angola and $0.2 million in the United Kingdom.

Liquidity

The Companyâ€™s primary source of capital has been cash flows from operations. At September 30, 2013, the Company had unrestricted cash of $100.5 million. The Company believes that this cash combined with cash flow from operations will be sufficient to fund the Companyâ€™s remaining 2013 and the 2014 capital expenditure budget, and additional investments in working capital resulting from potential growth. As operator of the Etame Marin and Mutamba Iroru blocks in Gabon, Block 5 in Angola, the Company enters into project related activities on behalf of its working interest partners. The Company generally obtains advances from its partners prior to significant funding commitments.

Substantially all of the Companyâ€™s crude oil and natural gas is sold at the well head at posted or index prices under short-term contracts. In Gabon, the Company markets its crude oil under an agreement with Mercuria Trading NV (â€śMercuriaâ€ť). While the loss of Mercuria as a buyer might have a material adverse effect on the Company in the near term, management believes that the Company would be able to obtain other customers for its crude oil in Gabon.
Domestic operated production in Texas is sold via two contracts, one for oil and one for gas and natural gas liquids. The Company has access to several alternative buyers for oil, gas, and natural gas liquids domestically.

RESULTS OF OPERATIONS

Three months ended September 30, 2013 compared to three months ended September 30, 2012

Total Revenues

Total oil and natural gas revenues were $37.7 million for the three months ended September 30, 2013 compared to $37.6 million the same period of 2012.

Oil Revenues

Gabon

Crude oil revenues for the three months ended September 30, 2013 were $37.3 million, as compared to $37.0 million for the same period in 2012. In the three months ended September 30, 2013, the Company sold approximately 337,000 net barrels of oil at an average price of $110.54/Bbl, while in the three months ended September 30, 2012 it sold approximately 342,000 net barrels of oil at an average price of $107.94/Bbl.

United States

Condensate sales from the Granite Wash formation wells, located in Hemphill County, Texas for the period ended September 30, 2013 were $0.1 million, resulting from the sale of approximately 1,600 net barrels of oil condensate at an average price of $88.83. For the same period in 2012, condensate sales were $0.2 million, resulting from the sale of approximately 2,300 net barrels of oil condensate at an average price of $77.48/Bbl.

Natural Gas Revenues

United States

Natural gas revenues including revenues from natural gas liquids for the three months ended September 30, 2013 were $0.3 million compared to $0.5 million for the same period in 2012. Natural gas sales volumes were 74 MMcf at an average price of $4.57/Mcf for the three months ended September 30, 2013, compared to sales volumes of 147 MMcf at an average price of $3.32/Mcf for the same period in 2012.

Operating Costs and Expenses

Production expenses for the three months ended September 30, 2013 were $12.6 million compared to $5.9 million for the same period in 2012. The higher production expenses in the three months ended September 30, 2013 compared to the same period in 2012 were attributable to offshore Gabon operations which included $2.1 million of well workover costs to replace electrical submersible pumps in an offshore Gabon well, $0.6 million of higher FPSO operating costs, $1.0 million related to deck boiler repairs onboard the FPSO, $0.8 million incurred for generator repairs on the Avouma platform, $0.7 million of costs to temporarily suspend the two Ebouri wells affected by elevated levels of H2S, and $0.8 million in higher costs resulting from crude oil inventory adjustments.
For the three months ended September 30, 2013, the Companyâ€™s Gabon production was approximately 16,900 BOPD (4,100 BOPD net to the Company), as compared to approximately 19,000 BOPD (4,600 BOPD net to the Company) for the same period in 2012.

Exploration expenses for the three months ended September 30, 2013 was $11.1 million, compared to $0.7 million for the same period in 2012. For the three months ended September 30, 2013, exploration expenses consisted primarily of dry hole costs of $6.0 million related to two offshore Gabon unsuccessful exploration wells, $3.0 million of dry hole costs related to a well drilled in the fourth quarter of 2012 in Roosevelt County, Montana where it was decided in the third quarter of 2013 to not proceed with additional completion activities, and $2.0 million to expense portions of undeveloped leaseholds held in Texas and Montana, United States. For the three months ended September 30, 2012, exploration expenses consisted primarily $0.3 million for activities in North America, $0.1 million for activities offshore Gabon, and $0.2 million for activities in Angola.

Depreciation, depletion and amortization expenses were $4.0 million in the three months ended September 30, 2013 compared to $4.9 million in the three months ended September 30, 2012. The lower depreciation, depletion and amortization expenses during the three months ended September 30, 2013 compared to the same period in 2012 were primarily due to both lower average depletion rates and lower sales volumes.

General and administrative expenses for the three months ended September 30, 2013 and 2012 were $1.9 million and $2.5 million, respectively. The decrease in general and administrative costs in the three months ended September 30, 2013 compared to the same period in 2012 was primarily due to higher overhead reimbursements resulting from the active development program offshore Gabon.

During the three months ended September 30, 2012, the Company recorded an impairment loss of $7.6 million to write down its investment in the Granite Was formation of North Texas to its fair value. The impairment charge was due to a combination of continued production declines from both wells and low natural gas prices.

Other Income (expense)

Other expense for the three months ended September 30, 2013 was $56,000, comprised principally of losses on foreign exchange transactions. Other income for the three months ended September 30, 2012 was $9,000.

Income Taxes

Income tax expense amounted to $5.7 million and $14.2 million for the three months ended September 30, 2013 and 2012, respectively. In the three months ended September 30, 2013 and 2012, the income taxes were all paid in Gabon. Income taxes in the three months ended September 30, 2013 were lower due to a lower percentage of oil allocated as â€śprofit oilâ€ť versus â€ścost oilâ€ť. The income taxes the consortium pays the government of Gabon is an allocation of the remaining profit oil production from a specific contract area ranging from 50% to 60% of the oil remaining after deducting the royalty and the cost oil.

Net Income

Net income for the three months ended September 30, 2013 was $2.4 million, compared to $0.1 million for the same period in 2012. Net income allocated to the noncontrolling interest was $1.3 million in the three months ended September 30, 2012.

The noncontrolling interest, which was associated with VAALCO Energy (International), Inc., a subsidiary that was 90.01% owned by the Company, was acquired by the Company at a cost of $26.2 million effective October 1, 2012.

Total oil and natural gas revenues were $111.0 million for the nine months ended September 30, 2013 compared to $141.7 million for the same period of 2012.

Oil Revenues

Gabon

Crude oil revenues for the nine months ended September 30, 2013 were $109.5 million, a $30.1 million decrease from revenues of $139.6 million for the same period of 2012. The Company sold approximately 1,013,000 net barrels of oil at an average price of $108.06/Bbl. in the nine months ended September 30, 2013. The Company sold approximately 1,248,000 net barrels of oil at an average price of $111.79/Bbl. in the nine months ended September 30, 2012. Sales volumes declined in the nine months ended September 30, 2013 as compared to the same period in 2012 primarily due to temporary production stoppages resulting from workover activities for replacing electrical submersible pumps on three offshore Gabon wells, as well as the July 2012 shut-in of two wells in the Ebouri field, offshore Gabon, as a precaution after detecting H2S.

United States

Condensate sales from the Granite Wash wells, located in Hemphill County, Texas for the nine months ended September 30, 2013 were $0.3 million, resulting from approximately 4,000 barrels of oil condensate at an average price of $83.88/Bbl. Condensate sales for the nine months ended September 30, 2012 were $0.6 million, resulting from approximately 7,300 barrels of oil condensate at an average price of $82.81/Bbl.

Natural Gas Revenues

United States

Natural gas revenues, including revenues from natural gas liquids, for the nine months ended September 30, 2013 were $1.2 million compared to $1.5 million for the comparable period in 2012. Natural gas sales volumes were 257 MMcf at an average price of $4.50/Mcf for the nine months ended September 30, 2013, compared to sales volumes of 421 MMcf at an average price of $3.65/Mcf for the same period in 2012.

Operating Costs and Expenses

Production expenses for the nine months ended September 30, 2013 were $28.0 million compared to $18.0 million in the nine months ended September 30, 2012. The higher production expenses in the nine months ended September 30, 2013 compared to the same period in 2012 were attributable to offshore Gabon operations which included $7.3 million of well workover costs to replace electrical submersible pumps in three offshore Gabon wells, $1.0 million related to deck boiler repairs onboard the FPSO, $0.8 million incurred for generator repairs on the Avouma platform, and $0.7 million to temporarily suspend the two Ebouri wells affected by elevated levels of H2S. The higher production expenses were partially offset by $0.7 million lower production costs resulting from crude oil inventory adjustments.

For the nine months ended September 30, 2013, the Companyâ€™s Gabon production was approximately 16,800 BOPD (4,100 BOPD net to the Company), as compared to approximately 20,100 BOPD (4,900 BOPD net to the Company) for the nine months ended September 30, 2012.
For the nine months ended September 30, 2013, exploration expense was $21.5 million, primarily including $11.4 million related to the Companyâ€™s unsuccessful exploration activities in the United States properties and $9.0 million dry-hole costs related to two unsuccessful offshore Gabon exploration wells. Additional exploration costs incurred in the nine months ended September 30, 2013 were $0.5 million onshore Gabon, $0.5 million offshore Gabon, and $0.2 million in Equatorial Guinea.

For the nine months ended September 30, 2012, exploration expense was $5.0 million, consisting primarily of a $2.9 million dry-hole charge to write-off the exploratory costs associated with the drilling and testing of several intervals below the Bakken/Three Forks formation on a well drilled in the East Poplar Dome field in Montana. Additional exploratory costs incurred in the nine months ended September 30, 2012 were $0.7 million in North America, $0.4 million onshore Gabon, and $0.6 million offshore Gabon, $0.2 million in Angola, and $0.2 million in the United Kingdom.
Depreciation, depletion and amortization expenses were $11.0 million in the nine months ended September 30, 2013 compared to $16.7 million in the nine months ended September 30, 2012. The lower depreciation, depletion and amortization expenses during the nine months ended September 30, 2013 compared to the same period in 2012 were primarily due to lower sales volumes in Gabon as a result of two wells shut-in for the H2S issue in July 2012 and three wells that underwent replacement of electrical submersible pumps.

General and administrative expenses for the nine months ended September 30, 2013 and 2012 were $8.0 million and $9.1 million, respectively. During the nine months ended September 30, 2013, the Company incurred $1.5 million higher administrative costs to support the increased overseas operations, offset by $2.7 million net credits from higher overhead reimbursements associated with production development operations on the Etame Marin block.
During the nine months ended September 30, 2012, the Company recorded an impairment loss of $7.6 million to write down its investment in the Granite Was formation of North Texas to its fair value. The impairment charge was due to a combination of continued production declines from both wells and low natural gas prices.

Other Income (expense)

Other expense for the nine months ended September 30, 2013 was $0.1 million, compared to other income of $0.7 million for the same period in 2012. The other expense and other income recorded in each of the nine months ended September 30, 2013 and 2012 were primarily attributable to foreign exchange transactions.

Income Taxes

Income tax expense amounted to $24.5 million and $60.7 million for the nine months ended September 30, 2013 and 2012, respectively. In the nine months ended September 30, 2013 and 2012, the income taxes were all paid in Gabon. Income taxes in the nine months ended September 30, 2013 were lower due to lower sales volumes and a lower percentage of oil allocated as â€śprofit oilâ€ť versus â€ścost oil.â€ť The income taxes the consortium pays the government of Gabon is an allocation of the remaining profit oil production from a specific contract area ranging from 50% to 60% of the oil remaining after deducting the royalty and the cost oil.

Net Income

Net income for the nine months ended September 30, 2013 was $16.7 million, compared to a net income of $19.6 million for the same period in 2012. Net income allocated to the noncontrolling interest for the nine months ended September 30, 2012 was $4.7 million.

The noncontrolling interest, which was associated with VAALCO Energy (International), Inc., a subsidiary that was 90.01% owned by the Company, was acquired by the Company at a cost of $26.2 million effective October 1, 2012.

CONF CALL

Robert Gerry - Chairman
Thank you, Linda, and good morning, ladies and gentlemen. And welcome to VAALCO Energyâ€™s third quarter conference call. Joining us today is VAALCOâ€™s new CEO, Steve Guidry; along with our President, Russell Scheirman; and Chief Financial Officer, Greg Hullinger.

Before I introduce Steve and turn the proceedings over to him, please bear with me while I read our Safe Harbor statement. This presentation call includes forward-looking statements within the meanings of Section 27A of the Securities Act of 1933 as amended and Section 21E of the Securities Exchange Act of 1934 as amended.

Forward-looking statements are those concerning VAALCOâ€™s plans, expectations and objectives for future drilling, completion and other operations and activities. All statements included in this conference call that address activities, events or developments that VAALCO expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements included expected capital expenditures, prospect evaluations, negotiations with governments and third parties, and reserve growth.

Investors are cautioned that forward-looking statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. These risks are further described in VAALCOâ€™s annual report on Form 10-K for the year ended December 31, 2012, and other reports filed with the SEC that can be reviewed at www.sec.gov.

Steve Guidry officially assumed the CEO position of VAALCO on October 21st, though he had spent the prior few weeks in our office familiarizing himself with all the internal and external operations and business of the company.

All of us here at VAALCO are excited over the new leadership and speaking for myself, Iâ€™m most impressed with his knowledge of the industry, his high level of energy and his astute business acumen. I truly believe VAALCO has found the right individual to successfully guide us in our next phase of growth.

Steve joins us after a highly successful career at Marathon Oil Company, where he covered the waterfront in a variety of positions with a strong emphasis on West Africa where as you all know VAALCO has a vast majority of its assets.

Steve is a petroleum engineer, by training with operations his strong suit as he has served Marathon for a number of years as their Central Africa business unit leader, encompassing Equatorial Guinea, Gabon and Angola, countries in which VAALCO has a vital vested interest.

He moved to Libya in 2009, where he became Chairman of the Waha Group, a joint venture between ConocoPhillips, Hess and Marathon. He returned to the U.S. to lead up Marathonâ€™s worldwide business development effort where he had the lead role in the $3.5 billion acquisitions by Marathon of acreage in the core area of the Eagle Ford.

I can tell you that not only is Steve a leader he is a team player and the Board is united in their belief that Steveâ€™s background and leadership we will be the catalyst VAALCO needs to successfully build and grow the company for the benefit of all of our stakeholders.